Sales Gas Enrichment with Propane and Butanes By IDS Process

ABSTRACT

The present invention is a separation unit process in which a high pressure section of a separation unit operates at a relatively high pressure to initially process and separate a high pressure feed stream and a low pressure section of the separation unit to initially process and separate a low pressure feed stream, where the high pressure section and the low pressure section are integral with and exchange streams to accomplish a desired separation of a wellhead fluid feed which typically includes a heavier portion of pentanes and heavier components

FIELD OF THE INVENTION

The present invention is broadly directed to the separation of well fluid stream(s) hydrocarbon components when main feed stream(s) to a single separation unit are provided at one or more substantially different pressures of hydrocarbon streams, such where production wells or upstream compression result in gathering feed streams to a separation unit at different pressures. The separation is accomplished in such away so that main product sales gas stream is fully enriched with propane and butanes contained in the hydrocarbon feed stream(s).

BACKGROUND OF THE INVENTION

It is well known to supply a well stream feed fluid to conventional gas processing plants mainly comprising a dew-pointing unit to produce sales gas with certain dew point spec and a liquid stabilization unit to produce a stabilized oil/condensate stream(s) meeting RVP specification. Commonly liquid from dew-pointing is directed to liquid stabilizer. If the feed fluid is typically rich in C2-C4 cut then NGL (mainly C3-C4) is built-up in the recycle stream from the stabilizer OVHD to LTS section ending to loss of revenue through flaring.

The natural gas separation unit is at a single pressure and thereafter to obtain desired product streams from that separation unit. Within the separation unit, for example, are chilling, turbo-expansion, J-T, compression and separation steps to accomplish a desired set of product streams. It is well known that a sales gas stream, stabilized condensate, and a stabilized bottoms oil streams are among those desired set of product streams. Commonly fuel gas needed is taken from sales gas stream containing propane and butanes components

Where wellhead production or upstream compression of one feed stream to a separation unit is substantially higher than another feed stream to the separation unit, the prior art separation unit will cause one stream to be reduced in pressure or the other stream to be compressed so that a single pressure feed stream is processed in the separation unit. Thus, where wellhead production or upstream compression of one feed stream causes it to be substantially greater than another feed stream to a separation unit, the prior art instructs one skilled in the art of natural gas separations to combine those two streams and to further process them at a single pressure.

Further, it is well known in the prior art of natural gas processing that “sales gas” is separated by low temperature separation in a thermodynamically single stage separation from wellhead natural gas in remote locations and transported away by pipeline to downstream central NGL recovery complex. Specifically and due to NGL build-up mentioned above, valuable amounts of propane and butanes are commonly flared in stabilizer OVHD compressed recycle gas especially for rich feed fluid and/or high CGR hydrocarbon feed fluid on-site near wellheads after gas-dew pointing and liquid stabilization to obtain sales gas. The economic incentive of maximizing recovery of propane and butanes by separating a maximum amount into sales gas to pipeline transportation together with having a robust and stable operation are obvious in those circumstances. However, the prior art comprises processes have failed to use sales gas transportation pipelines so recover a maximum amount of propane and/or butanes into sales gas, fractionating the sales gas to a safe margin within a certain gas dewpointing unit that will not result in hydrocarbon liquid condensation in the pipe line so that hydrocarbon liquid does not condense at transportation pipeline pressures and temperatures in all operating cases (summer, winter, turn down, etc.)

Sales gas specifications are well known in the art and comprises at least a maximum allowable hydrocarbon dewpoint temperature at a certain pressure. Generally, propane and butanes are permissible in sales gas product streams to an extremely low level, for example, often less than 0.2 mole percent, with the balance of heavier hydrocarbon components, for example, at less than 0.1 mole percent. This has led to significant problems in natural gas separations at remote locations, whereby levels of propane and butanes that cannot be released to the sales gas product accumulate in the internal process streams as a natural result of their typically low levels permitted in condensate and heavy oil product streams. Separation steps in the prior art natural gas processing in remote locations for gas dewpointing and condensate and/or sales oil product streams are associated with that NGL buildup of propane and butanes.

There is a need for a new process configuration for gas separation and condensate and/or oil stabilization unit process to overcome NGL build-up and ensure a stable plane operation in which a high pressure section of a separation unit operates at a relatively high pressure to initially process and separate a high pressure feed stream and a low pressure section of the separation unit to initially process and separate a low pressure feed stream, where the high pressure section and the low pressure section are integral with and exchange streams to accomplish a desired separation of a natural gas stream. Further, there is a need for a natural gas dew pointing and liquid stabilization process where sales gas fractionation and/or absorption control provides for increased levels of propane and butanes in the sales gas fraction and also to recover propane and butanes components from fuel gas taken from sales gas.

SUMMARY OF THE INVENTION

The present invention is a separation unit process in which a high pressure section of a separation unit operates at a relatively high pressure to initially process and separate a high pressure feed stream and a low pressure section of the separation unit to initially process and separate a low pressure feed stream, where the high pressure section and the low pressure section are integral with and exchange streams to accomplish a desired separation of a natural gas stream.

This present invention comprises integration of two primary processing sections. The first is a gas dewpointing section where extremely tight control to maximize heavier components in a sales gas is achieved within a required sales gas product dewpoint that includes a maximum permissible enrichment with propane and butanes as compared with the prior art to prevent buildup of propane and butanes in internal streams. The second section is a condensate and/or oil stabilization section. These two sections operated integrally to form what is referred to as the Integrated Dewponting and Stabilization (IDS) process.

A critical feature of the invention separation unit is a first separation stage for low pressure feed and a first separation stage for the high pressure feed, whereafter (1) liquid from the low pressure first separation stage is combined with liquid from the high pressure separation stage and (2) gas from the high pressure first separation stage is combined with compressed gas from the low pressure separation stage. These steps are critical to savings in equipment and energy in order to transfer desired portions of the low pressure feed to the high pressure section and desired portions of the high pressure feed to the low pressure section. The only other compression equipment necessary to accomplish the above transfers between the low pressure section and the high pressure section is a liquid pump for the liquid from the low pressure first separation stage to combine it with liquid from the high pressure separation stage. Thus, compression energy of the gas from the high pressure first separation stage is preserved by compressing only the lighter components of the low pressure feed in the gas from the low pressure separation stage and further processing that combined gas stream at a relatively higher pressure, thereby reducing ultimate gas compression requirements for a sales gas stream. The sales gas stream also comprises a separated portion of the gas from the high pressure first stage separation stage.

It is well known that local fuel gas for plant utilities like fired heaters, power generation, etc. in remote areas processing natural gas streams is a problem. Fuel gas for gas burners in fired heaters is typically required to have a relatively narrow range of components for optimum operation of the fired heater overall. While the gas burners can operate with components well outside of the recommended ranges, overall efficiency and operation of the fired heater suffers from using flames of fuel gas with very different component ranges than those used for an original design. Further, fuel gas generated from operation of a natural gas separation unit is often a portion of a desired sales gas product stream with substantial economic value as a stream having specification composition for which processing energy has been expended and for which equipment has been purchased.

The present invention has integrated into the operation of the high pressure section (gas dewpointing) and the low pressure section (oil/condensate stabilization) a fuel gas section that receives a portion of a combined stream after splitting off the sales gas product. The fuel gas section produces a fuel gas of desired component ranges of components that are of lesser economic value to the overall process, a substantial improvement over prior art natural gas separation processes by recovering propane and butanes contained in the fuel gas stream

The present invention requires, but not limited to, a closed loop propane refrigeration system for multiple heat exchange steps, but no colder temperatures than that required for external refrigeration sources for operation of the invention processes. Refrigeration is also provided by other low temperature separation technique e.g. JT, post chilling JT, turbo-expansion, etc.

A first invention separation unit operates to produce sales gas, fuel gas, sales condensate, and sales oil streams. A second invention separation unit operates to produce sales gas, fuel gas, and a stabilized oil stream. Both invention separation units operate using the above described first separation stages and exchange of gas and liquid streams, although downstream equipment and processing steps differ between the first and second invention separation units to achieve those desired product streams.

Further, the present invention in a second embodiment provides for a natural gas fractionation process where fractionation control provides for increased levels of propane and butanes in the sales gas fraction ensuring elimination of hydrocarbon build-up and hence no flaring. In some circumstances, as much as ninety-nine percent of propane and butanes in feed streams from wellhead production is recovered into and transported in a sales gas transportation pipeline to a distant NGL extraction complex. The distant processing facility optionally recover and separate the propane and butanes from the sales gas for separate product distribution.

Various objects and advantages of the present invention will become apparent from the following description taken in conjunction with the accompanying drawings wherein are set forth, by way of illustration and example, certain embodiments of this invention. The drawings submitted herewith constitute a part of this specification, include exemplary embodiments of the present invention, and illustrate various objects and features thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a process diagram of a first invention separation unit.

FIG. 2 is process diagram of a second invention separation unit.

FIG. 3 is table of stream data for the invention process shown in FIG. 1.

FIG. 4 is table of stream data for the invention process shown in FIG. 2.

DETAILED DESCRIPTION OF THE INVENTION

As required, detailed embodiments of the present invention are disclosed herein; however, it is to be understood that the disclosed embodiments are merely exemplary of the invention, which may be embodied in various forms. Therefore, specific structural and functional details disclosed herein are not to be interpreted as limiting, but merely as a basis for the claims and as a representative basis for teaching one skilled in the art to variously employ the present invention in virtually any appropriately detailed structure.

For FIG. 1 and FIG. 2 respectively, the table below identifies Case 1 and Case 2 stream properties for the HP FEED and LP FEED:

TABLE 1 Case 1 Case 2 Stream Name HP Feed LP Feed HP Feed LP Feed Vapour/Phase 0.846 0.8828 0.846 0.8828 Fraction Temperature: (F.) 118.4 116.6 118.4 116.6 Pressure: (psig) 347.9 159.4 347.9 159.4 Molar Flow (MMSCFD) 37.89 77.18 37.82 77.03 lbmole/hr lbmole/hr lbmole/hr lbmole/hr H2S 0.0342 0.0479 0.0342 0.0478 C02 129.6814 770.954 129.4318 769.4704 Nitrogen 5.026 44.3349 5.0153 44.2496 Methane 2782.996 4389.71 2777.541 4381.253 Ethane 338.567 1069.205 337.9155 1067.147 Propane 253.6511 850.2828 253.153 848.6466 i-Butane 41.7958 111.7108 41.7154 111.4958 n-Butane 79.6194 238.3153 79.4552 237.8567 i-Pentane 30.7994 70.5335 30.7402 70.3978 n-Pentane 18.4073 66.3256 18.3719 66.198 n-Hexane 46.3475 103.2587 46.2583 103.06 Mcyclopentan 8.2402 11.142 8.2243 11.1205 Benzene 4.1745 17.1261 4.1555 17.0931 Cyclohexane 14.7412 13.0956 14.7129 13.0704 n-Heptane 38.4825 67.6546 38.4084 67.5344 Mcyclohexane 11.9641 23.0526 11.9411 23.0082 Toluene 13.717 30.9059 13.6906 30.8474 n-Octane 26.1469 65.3477 26.0966 65.2219 E-Benzene 7.1035 5.1815 7.0899 5.1715 m-Xylene 5.4286 18.7832 5.4181 18.747 p-Xylene 5.4282 18.7827 5.4177 18.7455 o-Xylene 7.0571 5.3701 7.0435 5.3598 n-Nonane 19.1149 42.7054 19.0781 42.6232 123-MBenzene 2.5216 10.6106 2.5167 10.5902 n-Decane 22.0179 51.051 21.9756 50.9527 n-C11 20.6788 40.0311 20.639 39.954 n-C12 19.4382 33.5933 19.4008 33.5286 n-C13 17.6002 35.1023 17.5663 35.0347 n-C14 16.9555 31.7785 16.9229 31.7173 n-C15 16.3686 24.8783 16.3371 24.8304 n-C16 16.0545 21.211 16.0236 21.1702 n-C17 15.3106 16.3205 15.2811 16.2891 n-C18 14.4982 12.326 14.4703 12.3022 n-C19 13.0943 11.4437 13.0691 11.4217 n-C21 0.079 0.0789 0 H20 24.1269 98.2286 24.0805 98.0396 D-N C20+′ 9.9337 0 9.9146 M C20+′ 73.0238 5.8688 72.8833 5.8575 F C20+* 38.7932 0 38.7185

FIG. 1 comprises the first invention separation unit for two natural gas streams, HP FEED and LP FEED. Generally, a high pressure section is defined by streams fed to and produced from column Stab-1, a low pressure section is defined by streams fed to and produced from column T-101, and a fuel gas section is defined by streams fed to and produced from column T-100.

HP FEED at high pressure from wellhead production or upstream compressing is supplied to first separation drum V-101. LP FEED at lower pressure from wellhead production or other sources is supplied to first stage separation drum V-100.

The above described critical exchange of streams is shown at (1) gas stream 4 from drum V-101 is fed to separation drum V-108 to combine with a compressed and cooled stream in the low pressure section of the separation unit and (2) liquid stream 2 is pumped (pump not shown; as indicated in the drawing figures and in the stream data in FIGS. 3 and 4, an increase in pressure of a liquid stream in the invention processes indicates that a liquid pump has been used to raise the pressure of that liquid stream without showing a pump in the process diagrams of FIGS. 1 and 2) to a higher pressure and combined with the liquid stream 5 from drum V-101. Combined gas stream 36 from V-108 is processed in the low pressure section to produce the majority of the SALES GAS stream and the SALES CONDENSATE stream. Combined liquid stream 9 is processed in the high pressure section to produce the majority of the SALES OIL stream.

Beginning again with stream LP FEED, V-100 receives that stream and streams 35 and 38, all combining there to be separated into gas stream 1 and liquid stream 2. Stream 1 is compressed in compressor K-101 to form stream 41 and is air cooled in air cooler AC-102, forming stream 42, which is fed to drum V-107. Stream 42 is separated into liquid stream 35 (returned to drum V-100) and gas stream 33, which is fed into drum V-108 with gas stream 4 (from high pressure first stage separation drum V-101) and separated there into liquid stream 38 (returned to drum V-100) and gas stream 36, which is fed to combined unit U-1 to remove for acid gas, water and mercury to form a stream cooled in exchanger E105 to form stream 42. Stream 42 is fed to column T-101, which also receives liquid stream 72. Column T-101 comprises a propane refrigerant-cooled condenser and separator unit C2 to generate reflux for column T-101 and a reboiler R2 for reboiling column T-101. Column T-101 forms overhead gas stream 43, which is warmed in exchanger E-105 to form stream 52. Stream 52 is compressed in compressor K-102 to form stream 60, which is air cooled in air cooler AC-103 to form stream 62. Stream 62 is split into two gas stream, one treated in mole sieve dehydration unit U-2 to form stream 65 and the other compressed in compressor K-104 to form gas stream 60, which is cooled in air cooler AC-104 to form the stream SALES GAS to sales gas specifications. Column T-101 forms bottom stream 44, which is cooled in exchanger E-102 to form stream 45, which results in a liquid stream split into two streams, one stream SALES COND, which is sales condensate to well known specifications, and stream 50.

Referring again to FIG. 1, stream HP FEED is fed to drum V-101 and separated there into a gas stream 4 and a liquid stream 5, which is combined with liquid stream 2 (from low pressure first stage separation drum V-100) to form stream 9, which is warmed in exchanger E100 to form stream 10. Stream 10 is separated in drum V-103 into gas stream 11 (fed to column Stab-1) and a liquid stream which is treated in desalter U-3 (to remove salts) and warmed in exchanger E-101 to form stream 17, which is also fed to column Stab-1. Column Stab-1 comprises an air cooled condenser and separator unit C1 to generate reflux for column Stab-1 and a reboiler R1 for reboiling column Stab-1. Column Stab-1 produces overhead gas stream 18, which is compressed in compressor K-100 to form stream 21, which further is cooled in air cooler AC-100 to form stream 22 (which is fed to drum V107 with gas stream 32). Column Stab-1 produces a bottoms liquid stream 19 that is cooled in exchanger E-101 to form stream 23, which is further cooled in exchanger E-100 to form stream SALES OIL, which comprises the heavier components of the two feed streams which are not included in stream SALES CONDENSATE.

Stream 50 (from a bottoms stream of column T-101) and stream 65 (a portion of the overhead gas stream of column T-101) are cooled multi-stream exchanger LNG-100 against stream C3 a (a propane refrigerant stream) and streams 70 and 78. Stream 65 is cooled to form stream 66, which is fed to the bottom of column T-100, an absorber column. Stream 50 is cooled to form stream 51, which is combined with the overhead gas stream of column T-100, the combined stream being cooled in multi-stream exchanger LNG-101 against stream C3 b (a propane refrigerant stream) and streams 69 and 76 to form stream 74. Stream 74 is separated in drum V-103 to gas stream 76 and liquid stream 77. Liquid stream 77 is fed to the top stage of column T-100 to provide absorbing liquid. Gas stream 76 is warmed to form stream 78 and warmed again in multi-stream exchanger LNG-100 to form stream FUEL to provide specification range fuel gas.

Column T-100 produces an bottoms liquid stream 69, which is warmed in exchanger LNG-100 to form stream 71, which in turn is further warmed in exchanger E-102 to form stream 72, which is fed to column T-101.

FIG. 2 comprises the second invention separation unit for two natural gas streams, HP FEED and LP FEED. Generally, a high pressure section is defined by streams fed to and produced from column Stab-1, a low pressure section is defined by streams fed to and produced from column C5 SCRUBBER, and a fuel gas section is defined by streams fed to and produced from column T-100.

HP FEED at high pressure from wellhead production or upstream compressing is supplied to first separation drum V-101. LP FEED at lower pressure from wellhead production or other sources is supplied to first stage separation drum V-100.

The above described critical exchange of streams is shown at (1) gas stream 4 from drum V-101 is fed to separation drum V-108 to combine with a compressed and cooled stream in the low pressure section of the separation unit and (2) liquid stream 7 is pumped (pump not shown; as indicated in the drawing figures and in the stream data in FIGS. 3 and 4, an increase in pressure of a liquid stream in the invention processes indicates that a liquid pump has been used to raise the pressure of that liquid stream without showing a pump in the process diagrams of FIGS. 1 and 2) to a higher pressure and combined with the liquid stream from drum V-101 to form a combined stream 9. Combined gas stream 47 from V-108 is processed in the low pressure section to produce the majority of the SALES GAS stream. Combined liquid stream 9 is processed in the high pressure section to produce the majority of the STABILIZED OIL stream.

Beginning again with stream LP FEED, V-100 receives that stream and streams 46 and 48, all combining there to be separated into gas stream 1 and liquid stream 2. Stream 1 is compressed in compressor K-101 to form stream 41 and is air cooled in air cooler AC-102, forming stream 42, which is fed to drum V-107. Stream 42 is separated into liquid stream 46 (returned to drum V-100) and gas stream 47, which is fed into drum V-108 with gas stream 4 (from high pressure first stage separation drum V-101) and separated there into liquid stream 48 (returned to drum V-100) and gas stream 47, which is fed to combined unit U-1 to remove for acid gas, water and mercury to form a stream cooled in exchanger E105 to form stream 53. Stream 53 is further cooled in exchanger E-107 against propane refrigerant and fed to the bottom stage of column C5 SCRUBBER, an absorber column. Column C5 SCRUBBER receives stream 34 to a top stage to produce an overhead gas stream 55, which is warmed in exchanger E-105 to form stream 59. Stream 59 is combined with stream 30, the combined stream compressed in compressor K-102 to form stream 62, which is cooled in air cooler AC-103 to form stream 63. Stream 63 is split into two gas stream, one treated in mole sieve unit U-2 to form stream 72 and the other compressed in compressor K-104 to form gas stream 67, which is cooled in air cooler AC-104 to form the stream SALES GAS to sales gas specifications.

Referring again to FIG. 2, stream HP FEED is fed to drum V-101 and separated there into a gas stream 4 and a liquid stream, which is combined with liquid stream 7 (from low pressure first stage separation drum V-100) to form stream 9, which is warmed in exchanger E100 to form stream 10. Stream 10 is separated in drum V-103 into gas stream 11 (fed to column Stab-1) and a liquid stream which is treated in desalter U-3 (to remove salts) and warmed in exchanger E-101 to form stream 17, which is also fed to column Stab-1. Column Stab-1 comprises a reboiler R1 for reboiling column Stab-1. Column Stab-1 produces overhead gas stream 18, which is compressed in compressor K-100 to form stream 21, which further is cooled in air cooler AC-100 to form stream 22 which is fed to drum V-111.

A liquid stream 26 from drum V-111 is fed to a top stage of column Stab-1 to provide reflux for the column. The bottoms liquid stream 56 is cooled in exchanger E-103 to form stream 58, which is fed to column Stab-1 with stream 79. The gas stream 23 from drum V-111 is treated in TEG dehydration and mercury removed unit U-4 and is then split into two streams, one stream being cooled in air cooler AC-107 to form stream 32, which is in turn cooled in exchanger E-103 to form stream 33. Stream 33 is cooled in exchanger E-104 (against propane refrigerant) to form stream 34, which is fed to the top stage of column C5 SCRUBBER. The second of the split streams from stream 23 is stream 30, which is combined with stream 59 (from the overhead gas stream of column C5 SCRUBBER).

The processes of FIG. 1 and FIG. 2 provide for recovery of over 99% into SALES GAS of propane and butanes in the feed gases. Streams 18 of FIG. 1 and FIG. 2 represent a recycle stream that provides a load to compressor K-100. The present inventor has discovered that removal of propane and butanes into the sales gas eliminates a buildup of gas streams in the overhead stream from prior art stabilizers whose processes do not provide for removal of propane and butanes. That buildup of the gas stream propane and butanes has been found in the prior art to overwhelm the compressor in the position of the compressor K-100. The present invention has eliminated that overload problem entirely. The processes of the present invention can recover to the sales gas product at least 70 percent of the feed gas propane and butanes, more preferably 80 percent of the feed gas propane and butanes, and most preferably greater than 95 percent of the feed gas propane and butanes. Specifications for the sales gas product that must be met for pipeline transportation from the wellhead area to an area of further processing comprise that the sales gas product after a second compression step in the invention process exist in what is known at the “dense phase” for the highest pipeline pressures and/or near cricondenbar and critical area, which means that the invention process is operated so that the sales gas product in the transportation pipeline at its highest pressure exists under conditions that are within an acceptable margin (minimum operating temperature less dewpoint temperature) to avoid hydrocarbon liquid condensation at the lowest temperatures that will be experienced by the sales gas product in the transportation pipeline. As a practical consideration, in most circumstances, the present inventor has found that the sales gas product of the invention processes are delivered to the transportation pipeline at temperatures and pressures substantially above the critical point for the sales gas product, making the meeting of pipeline specifications for dewpoint of minimal concern.

It will be understood that the present invention embodiments for a process of separating hydrocarbon fluid feeds at two pressures can be thought of as a process for separating a hydrocarbon fluid feed at a single high pressure, where the above LP feed liquid is fed to the HP feed drum and the LP feed gas is compressed to a higher pressure or all of hydrocarbon fluid feed is provided at the pressure of the HP feed and processed as if there were no LP feed.

It is to be understood that while certain forms of the present invention have been illustrated and described herein, it is not to be limited to the specific forms or arrangement of parts described and shown. 

What is claimed is:
 1. A separation unit process for a hydrocarbon fluid feed from a wellhead source comprising: (a) separating the fluid feed in a high pressure drum to form an HP gas and an HP liquid; (b) reducing the pressure of the HP liquid to a low pressure and separating the low pressure HP liquid in a stabilizer column to form a sales oil product as a bottoms liquid product and a stabilizer overhead stream, which has hydrocarbon components that consist essentially of butanes and lighter components; (c) combining a compressed stabilizer overhead stream with the HP gas to be fed to a high pressure column operating at about the pressure of the natural HP gas feed, where a portion of a liquid bottoms stream of the high pressure column consists of a sales condensate stream recovering a portion of all hydrocarbon components of pentanes and heavier components in the fluid feed and a high pressure column overhead stream is compressed in a first compressor, where a portion of the compressed high pressure column overhead is further compressed to form a sale gas stream; (d) the balance of the compressed high pressure column overhead stream being cooled and fed to the bottom stage of an fuel gas absorber column operating at a substantially higher pressure than the high pressure column, where the fuel gas absorber column overhead stream is mixed with the balance of the liquid bottom stream of the high pressure column (pentanes plus), cooled and separated to form a fuel gas stream and an absorber liquid stream, which is fed to the top stage of the fuel absorber column; and (e) a fuel gas absorber liquid bottoms stream is fed to the high pressure column.
 2. The process of claim 1 wherein the sales gas product comprises 70 percent or more of the propane and butanes in the fluid feed.
 3. The process of claim 2 wherein the sales gas product meets specifications for a transportation pipeline in which the sales gas product is transported from a wellhead area.
 4. The process of claim 3 wherein the sales gas product consists of essentially all propane and butanes present in the fluid feed that for dewpoint specification requirements could not be separated into the sales gas product.
 5. The process of claim 4 wherein the hydrocarbon portion of the condensate product comprises essentially only pentanes and heavier components.
 6. The process of claim 4 wherein the hydrocarbon portion of the condensate product and stabilized oil product contain essentially all pentanes and heavier from the fluid feed.
 7. A separation unit process for a hydrocarbon fluid feed from a wellhead source comprising: (a) separating the hydrocarbon fluid feed in a high pressure drum to form an HP gas and an HP liquid; (b) reducing the pressure of the separated HP liquid to a low pressure and separating the low pressure HP liquid in a stabilizer column to form a stabilizer bottom stream, a portion of which is separated as a stabilized oil product, and a stabilizer overhead stream which has hydrocarbon components that consist essentially of pentanes and lighter components; (c) a first stabilizer overhead stream is compressed, cooled and separated to form a liquid reflux stream, fed to a first stage of the stabilizer column, and a second stabilizer overhead stream; (d) a portion of the second stabilizer overhead stream is cooled and fed to a first stage of a high pressure absorber operating at about the same pressure as the natural gas feed; (e) HP gas being cooled and fed to a bottom stage of the high pressure absorber, where the high pressure absorber overhead stream is mixed with the balance of the second overhead stabilizer stream, to form a mixed stream, where a portion of the mixed stream is further compressed to form a sale gas stream; (f) a high pressure absorber bottoms stream being fed to the stabilizer column; (g) the balance of the compressed mixed stream being cooled and fed to the bottom stage of an fuel absorber column operating at a substantially higher pressure than the high pressure column, where the fuel absorber column overhead stream is mixed with the balance of the liquid bottom stream of the high pressure column, cooled and separated to form a fuel gas stream and an absorber liquid stream, which is fed to the top stage of the fuel absorber column; and (h) a fuel absorber liquid bottoms stream is fed to the high pressure column.
 8. The process of claim 7 wherein the sales gas product comprises 70 percent or more of the propane and butanes in the fluid feed.
 9. The process of claim 8 wherein the sales gas product meets specifications for a transportation pipeline in which the sales gas product is transported from a wellhead area.
 10. The process of claim 9 wherein the sales gas product consists of essentially all propane and butanes present in the well fluid feed that for dewpoint specification requirements could not be separated into the sales gas product.
 11. The process of claim 10 wherein the hydrocarbon portion of the sales oil product comprises essentially only pentanes and heavier components.
 12. The process of claim 10 wherein the hydrocarbon portion of the sales oil product comprises almost all pentanes and heavier from the hydrocarbon well fluid feed.
 13. A separation unit process for a hydrocarbon fluid feed from a wellhead source comprising: (a) separating the fluid feed in a high pressure drum to form an HP gas and an HP liquid and separating the low pressure feed in a low pressure drum to form an LP gas and an LP liquid; (b) combining the LP liquid and HP liquid and separating the combined stream in a stabilizer column to form stabilizer liquid bottoms, all or a portion of which forms an oil product; and (c) compressing and cooling the LP gas and combining it with the HP gas, where a gas portion of the combined gas is separated in an LP column to form an LP column overhead gas, which is compressed and cooled, a portion of which is compressed and cooled to form a sales gas product.
 14. The process of claim 13 wherein the sales gas product comprises 70 percent or more of the propane and butanes in the fluid feed.
 15. The process of claim 14 wherein the sales gas product meets specifications for a transportation pipeline in which the sales gas product is transported from a wellhead area.
 16. The process of claim 15 wherein the sales gas product consists of essentially all propane and butanes that for dewpoint specification requirements could not be separated into the sales gas product.
 17. The process of claim 15 wherein the hydrocarbon portion of the condensate product comprises essentially only pentanes and heavier components.
 18. The process of claim 15 wherein the hydrocarbon portion of the condensate product comprises essentially all pentanes and heavier from the fluid feed. 